U.S. patent application number 13/053497 was filed with the patent office on 2011-10-06 for precipitation prevention in produced water containing hydrate inhibitors injected downhole.
This patent application is currently assigned to Baker Hughes Incorporated. Invention is credited to Cheryl R. Bailey, Jun Tian.
Application Number | 20110240915 13/053497 |
Document ID | / |
Family ID | 44708547 |
Filed Date | 2011-10-06 |
United States Patent
Application |
20110240915 |
Kind Code |
A1 |
Tian; Jun ; et al. |
October 6, 2011 |
Precipitation Prevention in Produced Water Containing Hydrate
Inhibitors Injected Downhole
Abstract
The precipitation of polymeric kinetic hydrate inhibitors (KHIs)
in stored produced water is prevented or inhibited by incorporating
a water immiscible solvent therein having a polarity index greater
than about 3. The polymeric KHIs whose precipitation is inhibited
or prevented include, but are not limited to, hyperbranched
molecules, polyvinylcaprolactam, polyvinylpyrrolidone, and the
like. Suitable water immiscible solvents include, but are not
necessarily limited to, xylene, toluene, kerosene, mineral spirits,
trimethylbenzene, cumene, heavy aromatic naphtha, ethylbenzene,
polyethylbenzene, naphthalene, and mixtures thereof.
Inventors: |
Tian; Jun; (League City,
TX) ; Bailey; Cheryl R.; (Sugar Land, TX) |
Assignee: |
Baker Hughes Incorporated
Houston
TX
|
Family ID: |
44708547 |
Appl. No.: |
13/053497 |
Filed: |
March 22, 2011 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61319477 |
Mar 31, 2010 |
|
|
|
Current U.S.
Class: |
252/182.29 ;
524/548; 524/555; 524/608 |
Current CPC
Class: |
C08L 77/12 20130101;
C08L 33/26 20130101; C09K 2208/22 20130101; C09K 8/524
20130101 |
Class at
Publication: |
252/182.29 ;
524/548; 524/555; 524/608 |
International
Class: |
C08L 77/00 20060101
C08L077/00; C09K 3/00 20060101 C09K003/00; C08L 39/00 20060101
C08L039/00; C08L 33/26 20060101 C08L033/26; C08L 39/06 20060101
C08L039/06 |
Claims
1. A method for inhibiting the precipitation of a polymeric kinetic
hydrate inhibitor (KHI) from an aqueous composition containing
water and at least one polymeric KHI comprising contacting the
aqueous composition with a water immiscible solvent having a
polarity index greater than about 3 in an amount effective to
inhibit the precipitation of the polymeric KHI.
2. The method of claim 1 where at least a portion of the water is
produced from a subterranean formation in a hydrocarbon recovery
operation.
3. The method of claim 1 where the amount of water immiscible
solvent ranges up to about 25 vol % of the water in the aqueous
composition.
4. The method of claim 1 where the amount of water immiscible
solvent ranges from about 1 to about 3 vol % of the water in the
aqueous composition.
5. The method of claim 1 where the water immiscible solvent is
selected from the group consisting of xylene, toluene, kerosene,
mineral spirits, trimethylbenzene, cumene, heavy aromatic naphtha,
ethylbenzene, polyethylbenzene, naphthalene, and mixtures
thereof.
6. The method of claim 1 where the aqueous composition comprising
the polymeric KHI, water and the solvent comprises: a viscosity
less than 100 cP (0.1 Pa-sec), an aqueous phase pH between about 1
and about 13, and salinity up to 300,000 mg/L at a temperature in
the range between about 85 to about 300.degree. F. (about 29 to
about 149.degree. C.).
7. The method of claim 1 further comprising storing the produced
water with the solvent in a storage facility.
8. The method of claim 7 where the storage facility is an
underground aquifer.
9. The method of claim 1 where the water in the aqueous composition
further comprises at least one salt and is a brine.
10. The method of claim 1 where the polymeric KHI is selected from
the group consisting of hyperbranched molecules,
polyvinylcaprolactam, polyvinylpyrrolidone,
poly(vinylcaprolactam-co-vinylpyrrolidone),
polyisopropylmethacrylamide, poly(N-vinyl-N-methylacetamide)
(VIMA), poly(VIMA:VCap) copolymer, poly(isobutylacrylamide),
hydroxyethyl cellulose and its derivatives, and mixtures
thereof.
11. A method for inhibiting the precipitation of a polymeric
kinetic hydrate inhibitor (KHI) from an aqueous composition
containing water and at least one polymeric KHI comprising
contacting the aqueous composition with a water immiscible solvent
having a polarity index greater than about 3 in an amount of up to
about 25 vol % of the water in the aqueous composition, where at
least a portion of the water is produced from a subterranean
formation in a hydrocarbon recovery operation, and where the water
immiscible solvent is selected from the group consisting of xylene,
toluene, kerosene, mineral spirits, trimethylbenzene, cumene, heavy
aromatic naphtha, ethylbenzene, polyethylbenzene, naphthalene, and
mixtures thereof.
12. The method of claim 11 further comprising storing the produced
water with the solvent in a storage facility.
13. An aqueous composition inhibited against the precipitation of
polymeric kinetic hydrate inhibitors (KHIs) comprising: water; at
least one polymeric KHI; and a water immiscible solvent having a
polarity index greater than about 3, in an amount effective to
inhibit the precipitation of the polymeric KHI.
14. The composition of claim 13 where at least a portion of the
water is produced from a subterranean formation in a hydrocarbon
recovery operation.
15. The composition of claim 13 where the amount of water
immiscible solvent ranges up to about 25 vol % of the water in the
composition.
16. The composition of claim 13 where the amount of water
immiscible solvent ranges from about 1 to about 3 vol % of the
water in the composition.
17. The composition of claim 13 where the water immiscible solvent
is selected from the group consisting of xylene, toluene, kerosene,
mineral spirits, trimethylbenzene, cumene, heavy aromatic naphtha,
ethylbenzene, polyethylbenzene, naphthalene, and mixtures
thereof.
18. The composition of claim 13 where the aqueous composition
comprising the polymeric KHI, water and the solvent comprises: a
viscosity less than 100 cP (0.1 Pa-sec), an aqueous phase pH
between about 1 and about 13, and a salinity up to 300,000 mg/L at
a temperature in the range between about 100 to about 300.degree.
F. (about 29 to about 149.degree. C.).
19. The composition of claim 13 where the polymeric KHI is selected
from the group consisting of hyperbranched molecules,
polyvinylcaprolactam, polyvinylpyrrolidone,
poly(vinylcaprolactam-co-vinylpyrrolidone),
polyisopropylmethacrylamide, poly(N-vinyl-N-methylacetamide)
(VIMA), poly(VIMA:VCap) copolymer, poly(iso-butylacrylamide),
hydroxyethyl cellulose and its derivatives, and mixtures
thereof.
20. An underground aquifer comprising the aqueous composition of
claim 13.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application claims the benefit of U.S. Provisional
Patent Application No. 61/319,477 filed Mar. 31, 2010.
TECHNICAL FIELD
[0002] The invention relates to methods and compositions for
inhibiting the precipitation of polymeric kinetic gas hydrate
inhibitors, and most particularly relates, in one non-limiting
embodiment, to methods and compositions for inhibiting the
precipitation of polymeric kinetic hydrocarbon hydrates in produced
water in long term storage.
BACKGROUND
[0003] A number of hydrocarbons, especially lower-boiling or
"light" hydrocarbons, in hydrocarbon formation fluids or natural
gas are known to form hydrates in conjunction with the water
present in the system under a variety of conditions--particularly
at a combination of lower temperature and higher pressure. The
hydrates usually exist in solid forms that are essentially
insoluble in the fluid itself. As a result, any solids in a
formation or natural gas fluid are at least a nuisance for
production, handling and transport of these fluids. It is not
uncommon for hydrate solids (or crystals) to cause plugging and/or
blockage of pipelines or transfer lines or other conduits, valves
and/or safety devices and/or other equipment, resulting in
shut-down, loss of production and risk of explosion or unintended
release of hydrocarbons into the environment either on land or
off-shore. Accordingly, hydrocarbon hydrates have been of
substantial interest as well as concern to many industries,
particularly the petroleum and natural gas industries.
[0004] Hydrocarbon hydrates are clathrates, and are also referred
to as inclusion compounds. Clathrates are cage structures formed
between a host molecule and a guest molecule. A hydrocarbon hydrate
generally is composed of crystals formed by water host molecules
surrounding the hydrocarbon guest molecules. The smaller or
lower-boiling hydrocarbon molecules, particularly C.sub.1 (methane)
to C.sub.4 hydrocarbons and their mixtures, are more problematic
because it is believed that their hydrate or clathrate crystals are
easier to form. For instance, it is possible for ethane to form
hydrates at as high as 4.degree. C. at a pressure of about 1 MPa.
If the pressure is about 3 MPa, ethane hydrates can form at as high
a temperature as 14.degree. C. Even certain non-hydrocarbons such
as carbon dioxide, nitrogen and hydrogen sulfide are known to form
hydrates under the proper conditions.
[0005] Species that tend to form hydrates at hydrate forming
conditions in the presence of water include lighter or low-boiling,
C.sub.1-C.sub.5, hydrocarbon gases, non-hydrocarbon gases or gas
mixtures at ambient conditions. Examples of such gases include, but
are not necessarily limited to, methane, ethane, ethylene,
acetylene, propane, propylene, methylacetylene, n-butane,
isobutane, 1-butene, trans-2-butene, cis-2-butene, isobutene,
butene mixtures, isopentane, pentenes, natural gas, carbon dioxide,
hydrogen sulfide, nitrogen, oxygen, argon, krypton, xenon, and
mixtures thereof. These molecules are also termed hydrate-forming
guest molecules herein. Other examples include various natural gas
mixtures that are present in many gas and/or oil formations and
natural gas liquids (NGL). The hydrocarbons may also comprise other
compounds including, but not limited to CO, CO.sub.2, COS,
hydrogen, hydrogen sulfide (H.sub.2S), and other compounds commonly
found in gas/oil formations or processing plants, either naturally
occurring or used in recovering/processing hydrocarbons from the
formation or both, and mixtures thereof.
[0006] Generally, there are two broad techniques to overcome or
control the hydrocarbon hydrate problems, namely thermodynamic and
kinetic. For the thermodynamic approach, there are a number of
reported or attempted methods, including water removal, increasing
temperature, decreasing pressure, addition of "antifreeze" to the
fluid and/or a combination of these. The kinetic approach generally
attempts (a) to prevent the smaller hydrocarbon hydrate crystals
from agglomerating into larger ones (known in the industry as an
anti-agglomerate and abbreviated AA) and/or (b) to inhibit, retard
and/or prevent initial hydrocarbon hydrate crystal nucleation;
and/or crystal growth (known in the industry as a kinetic hydrate
inhibitor and abbreviated KHI). Thermodynamic and kinetic hydrate
control methods may be used in conjunction.
[0007] Kinetic efforts to control hydrates have included the use of
different materials as inhibitors. For instance, onium compounds
with at least four carbon substituents are used to inhibit the
plugging of conduits by gas hydrates. Additives such as polymers
with lactam rings have also been employed to control clathrate
hydrates in fluid systems. These kinetic inhibitors are commonly
labeled Low Dosage Hydrate Inhibitors (LDHI) in the art because
they may be effectively used to inhibit hydrate formation at dosage
levels relatively lower than other inhibitors. KHIs and even LDHIs
are relatively expensive materials, and it is always advantageous
to determine ways of lowering the usage levels of these hydrate
inhibitors while maintaining effective hydrate inhibition.
[0008] Another particularly useful group of hydrate inhibitors
include dendrimeric compounds and in particular hyperbranched
polyester amides. Dendrimeric compounds are in essence
three-dimensional, highly branched oligomeric or polymeric
molecules comprising a core, a number of branching generations and
an external surface composed of end groups. A branching generation
is composed of structural units which are bound radially to the
core or to the structural units of a previous generation and which
extend outward from the core. The structural units may have at
least two reactive monofunctional groups and/or at least one
monofunctional group and one multifunctional group. The term
"multifunctional" is understood as having a functionality of about
2 or higher. To each functionality a new structural unit may be
linked, a higher branching generation being produced as a result.
The structural units may be the same for each successive generation
but they can also be different. The degree of branching of a
particular generation present in a dendrimeric compound is defined
as the ratio between the number of branchings present and the
maximum number of branchings possible in a completely branched
dendrimer of the same generation. The term "functional end groups"
of a dendrimeric compound refers to those reactive groups which
form part of the external surface. Branchings may occur with
greater or lesser regularity and the branchings at the surface may
belong to different generations depending on the level of control
exercised during synthesis. Dendrimeric compounds may have defects
in the branching structure, may also be branched asymmetrically or
have an incomplete degree of branching in which case the
dendrimeric compound is said to contain both functional groups and
functional end groups. In one non-limiting embodiment herein, the
term "highly branched" may refer to three-dimensional structures
that contain a combination of at least 5 functional groups and/or
at least 5 functional end groups. Alternatively or in addition to
these parameters, "highly branched" dendrimeric compounds may have
a number average molecular weight in the range of from about 1000
to about 5000, with a molecular weight distribution of as broad as
about 2 to about 30.
[0009] Dendrimeric compounds have also been referred to as
"starburst conjugates". Such compounds are described as being
polymers characterized by regular dendrimeric (tree-like) branching
with radial symmetry.
[0010] Functionalized dendrimeric compounds are characterized by
one or more of the reactive functional groups present in the
dendrimeric compounds having been allowed to react with active
moieties different from those featured in the structural units of
the starting dendrimeric compounds. These moieties can be
selectively chosen such that, with regard to its ability to prevent
the growth or agglomeration of hydrate crystals, the functionalized
dendrimeric compound out performs the dendrimeric compound. All of
these LDHIs are more fully described in U.S. Pat. No. 6,905,605
which is incorporated by reference herein in its entirety.
[0011] In addition to dendrimeric oligomers or polymers, suitable
gas hydrate inhibitors also include linear polymers and copolymers,
such as polymers and copolymers of vinylcaprolactam and/or
vinylpyrrolidone, or "onium" compounds such as tetrabutylammonium
bromide. Acceptable onium compounds include those mentioned in U.S.
Patent Application Publication 2005/0261529 A1, incorporated by
reference herein in its entirety.
[0012] Hydrate inhibitors are injected into flow lines of produced
hydrocarbons, such as oil and gas, that come from subsea wells to
prevent the formation of hydrates as the hydrocarbons are being
transported to other operations, such as a production facility, the
hydrate inhibitors stay with the aqueous phase of these streams
unless they are subsequently separated out. These compositions are
particularly useful for inhibiting, retarding, mitigating,
reducing, controlling and/or delaying formation of hydrocarbon
hydrates or agglomerates of hydrates in fluids, particularly those
used in hydrocarbon recovery operations. The method may be applied
to prevent or reduce or mitigate plugging of annular spaces, pipes,
transfer lines, valves, and other conduits, and places or equipment
downhole where hydro-carbon hydrate solids may form under
conditions conducive to their formation or agglomeration.
[0013] The term "inhibiting" is used herein in a broad and general
sense to mean any improvement in preventing, controlling, delaying,
reducing or mitigating the formation, growth and/or agglomeration
of hydrocarbon hydrates, particularly light hydrocarbon gas
hydrates in any manner, including, but not limited to kinetically,
thermodynamically, by dissolution, by breaking up, by
anti-agglomeration other mechanisms, or any combination thereof.
Although the term "inhibiting" is not intended to be restricted to
the complete cessation of gas hydrate formation, it may include the
possibility that formation of any gas hydrate is entirely
prevented.
[0014] The terms "formation" or "forming" relating to hydrates are
used herein in a broad and general manner to include, but are not
limited to, any formation of hydrate solids from water and
hydrocarbon(s) or hydrocarbon and non-hydrocarbon gas(es), growth
of hydrate solids, agglomeration of hydrates, accumulation of
hydrates on surfaces, any deterioration of hydrate solids plugging
or other problems in a system and combinations thereof.
[0015] The term "low dosage" used with respect to low dosage
hydrate inhibitors (LDHIs) as defined herein refers to volumes of
less than 5 volume % (vol %) of the fluids susceptible to hydrate
formation. In some non-limiting embodiments, the vol % for
thermodynamic hydrate inhibitors may be considerably higher, which
depends on both the system sub-cooling and hold time.
[0016] As noted, common KHIs and LDHIs are polymeric, including,
but not necessarily limited to, HYBRANE.RTM. hyperbranched polymers
available from DSM Hybrane, polyvinylcaprolactam (PVCap),
polyvinylpyrrolidone, poly(vinylcaprolactam-co-vinylpyrrolidone),
polyisopropylmethacrylamide, poly(N-vinyl-N-methylacetamide)
(VIMA), poly(VIMA:VCap) copolymer, poly(isobutylacrylamide),
hydroxy-ethyl cellulose and its derivatives, and mixtures thereof.
Even though these KHIs have relatively low molecular weights, they
are typically introduced into the fluids being treated in a
solvent, such as monoethylene glycol (MEG), butyl glycol ether
(BGE) and methanol (MeOH). These polymeric KHIs have shown some
complications in aqueous phase at elevated temperatures, for
instance, greater than 100.degree. F. (38.degree. C.),
specifically, they tend to precipitate as solids which potentially
present plugging problems.
[0017] In disposing of produced water in a subterranean aquifer,
such as to ultimate dispose of waste water, it is generally assumed
that a large amount of water is already present in the formation.
Trying to re-solubilize already-formed precipitates, such as by
using MEG, methanol (MeOH) or BGE would be expected to merely
removing the polymer precipitates from the periphery of or the
outside of the formation only temporarily, since polar solvents
would play a role in preventing precipitating of the polymeric KHIs
only when they are present in relatively high percentages of the
aqueous phase. When they contact more water and are diluted further
inside the aquifer, the polymeric KHIs would again precipitate out
of the solvents and potentially block the formation, preventing
further produced water from being introduced.
[0018] It is thus desirable to discover methods and compositions
for inhibiting the formation of precipitates in produced water that
is stored or disposed of.
SUMMARY
[0019] There is provided, in one non-limiting form, a method for
inhibiting the precipitation of a polymeric kinetic hydrate
inhibitor (KHI) from an aqueous composition containing water and at
least one polymeric KHI. The method includes contacting the aqueous
composition with a water immiscible solvent having a polarity index
greater than about 3 in an amount effective to inhibit the
precipitation of the polymeric KHI. In one non-limiting embodiment,
at least a portion of water is produced water. The method also
involves storing the produced water with the solvent in a storage
facility. As defined herein a storage facility includes, but is not
necessarily limited to, subterranean aquifers, subterranean
formations, tanks, vessels, and combinations thereof. It will be
appreciated that alternatively, the aqueous composition may be
stored first and then the water immiscible solvent added thereto as
long as the water immiscible solvent is sufficiently mixed with the
aqueous composition to prevent or inhibit precipitation of the
polymeric KHI from substantially all of the aqueous composition
stored. The water may be "produced water", that is water produced
as a by-product in the recovery of hydrocarbons (e.g. oil and gas)
from a subterranean formation.
[0020] Additionally there is provided in another non-restrictive
embodiment, an aqueous composition inhibited against the
precipitation of polymeric kinetic hydrate inhibitors (KHIs), where
the aqueous composition includes water, at least one polymeric KHI,
and a water immiscible solvent having a polarity index greater than
about 3, in an amount effective to inhibit the precipitation of the
polymeric KHI, for instance as compared with an identical
composition in identical conditions without the water immiscible
solvent. Again, in one non-restrictive version, at least a portion
of water is produced water.
DETAILED DESCRIPTION
[0021] Polymeric kinetic hydrate inhibitors (KHIs) are known to
inhibit the formation of gas hydrates at hydrate forming conditions
of high pressure and low temperature when water is present. For
example, HYBRANE.RTM. hyperbranched polymers available from DSM
Hybrane are known gas hydrate inhibitors, but these polymers have
shown some complications in monoethylene glycol (MEG) at elevated
temperatures, e.g. about 100 to about 300.degree. F. (about 38 to
about 149.degree. C.). For instance, in some embodiments at
temperatures above about 125.degree. F. (52.degree. C.) the
polymeric KHIs precipitate out. When volumes on the order of 6000
barrels (954 m.sup.3) of water a day are pumped into an aquifer for
disposal, the precipitation of the polymeric KHIs may
problematically block or clog the aquifer before the ultimate water
disposal capacity of the aquifer is reached.
[0022] Otherwise, good solubility of both HYBRANE polymers and
polyvinylcaprolactam (PVCap), another known gas hydrate inhibitor,
has been observed in polar solvents. These gas hydrate inhibitors
have relatively low molecular weights (for instance on the order of
about 2000 to about 3000 number average molecular weight), but even
so there are precipitation concerns when produced water containing
them is introduced into a storage facility, such as a subterranean
aquifer. Generally, there is not much information known about such
aquifers. Assuming that there is already a large amount of water
present inside the aquifer formation, solubilizing the polymeric
KHIs by monoethylene glycol (MEG), methanol (MeOH) or butyl glycol
ether (BGE) would be simply a measure to eradicate or redissolve
the active polymeric KHIs off of the outside periphery or the
outward and more accessible portions of the formation temporarily
since polar solvents such as those mentioned would play a role in
the polymeric KHIs' precipitation phase behavior only when they are
present in a relative high percentage of the aqueous phase. That
is, when they contact larger amounts of water and are diluted
further inside the aquifer, the polymeric KHIs would precipitate
out of these polar solvents and still potentially block and clog
the formation.
[0023] There may be several possible technical protocols to address
the problem of hydrate formation within produced water introduced
into aquifers, including breaking up the active polymeric KHIs by
hydrolysis, separating out the precipitant from the water before
downhole injection and dissolving the hydrates back into the fluid
system. As noted above, the use of polar solvents may not be the
correct approach. Thus, the inventors have sought to identify water
immiscible solvents that may be able to extract all or most of the
polymeric KHIs into its own phase, even at elevated temperatures,
while the entire system remains at relatively low viscosity.
[0024] A number of water immiscible solvents have been identified
based on known polarities from the literature, while also taking
into account the availability of such solvents in relatively large
volumes at relatively low cost. Additionally, boiling points and
flash points were considered in the selection of the solvents.
[0025] Water immiscible solvents expected to be useful include
polar solvents having a polarity index of greater than about 3. The
polarity index is a measure of the polarity of the solute-solvent
interactions. It depends strongly on the organic solvent, and
somewhat on the polar groups present in the phase. These solvents
include, but are not necessarily limited to, one or more of,
xylene, toluene, kerosene, mineral spirits, trimethylbenzene
(including isomers 1,2,4-trimethylbenzene, 1,3,5-trimethylbenzene,
and/or 1,2,3-trimethylbenzene), cumene, heavy aromatic naphtha,
ethylbenzene, polyethylbenzene; naphthalene, and mixtures thereof.
In some cases aromatic solvents work better, but it depends upon
the active chemical structure of the polymeric KHIs. It has been
discovered that for polar solvents, there is no apparent effect on
precipitation with up to 2 vol % based on the water present.
However for non-polar solvents a dramatic improvement in the
prevention of polymeric KHI precipitation has been seen with
COSDENOL 104 available from Total, which is a mixture of heavy
aromatic naphtha (58%), trimethylbenzene (25%), xylene (19%) and
cumene (7%), as well as with Aromatic 150 and xylene, even with
solvent volumes as low as about 1 vol % based on the water
present.
[0026] In general, "naphtha" does not have a specific definition
and can refer to a number of different flammable liquid mixtures of
hydrocarbons. One definition, found in N. Irving Sax, et al.,
Hawley's Condensed Chemical Dictionary, Eleventh Edition, Van
Nostrand Reinhold, New York, 1987, p. 806 is that naphtha is a
general term applied to refined, partly refined, or unrefined
petroleum products and liquid products of natural gas, not less
than 10% of which distill below 347.degree. F. (175.degree. C.) and
not less than 95% of which distill below 464.degree. F.
(240.degree. C.) when subjected to distillation in accordance with
the Standard Method of Test for Distillation of Gasoline, Naphtha,
Kerosene, and Similar Petroleum Products (ASTM D86). Heavy naphthas
are rather denser types and are usually richer in naphthenes and
aromatics. One definition of heavy aromatic naphtha is that it
consists predominantly (greater than 50 volume %) of C9 to C11
aromatic or naphthenic hydrocarbons, most (a subset of greater than
50 vol %) of those of which have 10 carbon atoms.
[0027] Other particular products expected to be useful in the
compositions and methods herein include, but are not necessarily
limited to, Aromatic 150 Hydrocarbon Fluid available from
ExxonMobil Chemical (greater than 99 vol % aromatics content but
less than 1 ppm benzene), Aromatic 100 Hydrocarbon Fluid available
from ExxonMobil Chemical (1,2,4-trimethylbenzene,
1,3,5-trimethylbenzene, and/or 1,2,3-trimethylbenzene, xylene and
cumene with less than 1 ppm benzene), AS 160 available from Nisseki
Chemicals Texas Inc. (99% polyethylbenzene residue and 1%
naphthalene), and FINASOL 150 available from Total Petrochemicals
(up to 99 wt % heavy aromatic naphthas, 5-15 wt % naphthalene and
about 0.5 wt % polynuclear aromatics). Less pure organic solvents
described in the paragraphs above may be used to confer lower cost
to the finished products.
[0028] Polar solvents that did not work to prevent precipitation of
the polymeric KHIs included isobutyl alcohol, methyl isobutyl
ketone (MIBK) and ethyl acetate.
[0029] The organic phase of the aqueous composition inhibited
against the precipitation of the polymeric KHIs may include, but
not necessarily be limited to (1) stand-alone streams from
commercial resources, (2) mixtures of different kinds, (3) produced
water from the recovery of hydrocarbons from subterranean
formations, e.g. the oil field, and (4) mixtures of produced
hydrocarbon with commercial solvents.
[0030] The amount of water immiscible solvent ranges up to about 25
vol % of the water in the aqueous composition. Alternatively, the
amount of water immiscible solvent ranges from about 1
independently to about 5 vol % of the water in the aqueous
composition, in another non-limiting version from about 1
independently to about 2 vol %. As used herein with respect to
parameter ranges the term "independently" means that any lower
threshold may be combined with any upper threshold to give a
suitable alternative range for the parameter. The water immiscible
solvent may be mixed or introduced into the aqueous composition by
any suitable technique or equipment including, but not limited to,
in-line mixers, stirrers, paddles, etc. and the like.
[0031] The aqueous composition including the polymeric KHIs and the
solvent in one non-limiting embodiment may have a viscosity less
than 100 cP (0.1 Pa-sec) at room temperature (20.degree. C.), an
aqueous phase pH between about 1 independently to 13, and salinity
up to 300,000 mg/L with system temperature in the range between
about 85 to about 300.degree. F. (about 29 to about 149.degree.
C.). In alternative embodiments, the aqueous composition may have a
viscosity between about 1 independently to about 3 cP at room
temperature and a pH between about 3 independently to about 11 and
a salinity of less than sea water, that is, less than 3 wt % salt.
Without the water immiscible solvents, the composition may be
sticky, like a gum or glue, which makes pumping and/or separation
difficult. The compositions must then be heated to reduce their
viscosity and improve their mobility.
[0032] To some extent, the viscosity depends on the pumping
capacity. In one non-limiting embodiment, the viscosity of the
organic phase should not be more viscous than the crude oil from
which the produced water is obtained (e.g. 100 cP (0.1 Pa-sec)) to
keep its mobility, and should at least be of sufficiently low
viscosity so that it may be pumped into the formation, aquifer or
other storage facility easily. Viscosity also depends on the phase
separation that occurs in the aqueous phase when the polymeric KHIs
separate and which temperatures and salinity levels cause such
phase separation or precipitation.
[0033] Other methods of addressing the problem of the polymeric
KHIs precipitating upon storage include extraction of the polymeric
KHIs from the water prior to storage (e.g. injection in an
aquifer), such as from the produced water, which extraction may
include heating the composition. Alternatively, adding more salt to
the aqueous composition, that is, the produced water, may
precipitate the polymeric KHIs out of the aqueous phase to
facilitate their removal.
[0034] The brines mentioned herein may be any typical brines, such
as those formed by salts including, but not necessarily limited to,
chlorides, bromides, formates. Specific suitable salts for forming
the brines include, but are not necessarily limited to, sodium
chloride, calcium chloride, zinc chloride, potassium chloride,
potassium bromide, sodium bromide, calcium bromide, zinc bromide,
sodium formate, potassium formate, ammonium formate, cesium
formate, and mixtures thereof. Brines of NaCl were used for the
experimental study, but little difference was observed between NaCl
and other salts with respect to the effect of precipitation of
active KHI inhibitors.
[0035] Many modifications may be made in the compositions and
methods of this invention without departing from the spirit and
scope thereof that are defined only in the appended claims. For
example, the polymeric hydrate inhibitors and water immiscible
solvent may be different from those explicitly mentioned herein.
Various combinations of water immiscible solvents alone or together
other than those described here are also expected to be useful.
Further, polymeric KHIs and water immiscible solvents herein used
alone or together with mixtures of water, hydrocarbons and
hydrate-forming guest molecules different from those exemplified
herein would be expected to be successful within the context of
this invention. The methods and compositions described herein are
also expected to be useful in the disposal and/or storage of
aqueous solutions in facilities other than subterranean aquifers,
for instance storage tanks and separators.
[0036] The present invention may suitably comprise, consist or
consist essentially of the elements disclosed and may be practiced
in the absence of an element not disclosed. For instance, the
method for inhibiting the precipitation of a polymeric kinetic
hydrate inhibitor (KHI) from an aqueous composition containing
water and at least one polymeric KHI may consist essentially of or
consist of contacting the aqueous composition with a water
immiscible solvent having a polarity index greater than about 3, as
these components are defined in the claims, in an amount effective
to inhibit the precipitation of the polymeric KHI and storing the
produced water with the solvent in a storage facility.
[0037] Additionally, the aqueous composition inhibited against the
precipitation of polymeric kinetic hydrate inhibitors (KHIs) may
consist essentially of or consist of water, at least one polymeric
KHI, and a water immiscible solvent having a polarity index greater
than about 3, in an amount effective to inhibit the precipitation
of the polymeric KHI. In another non-limiting embodiment, the
method for inhibiting the precipitation of a polymeric kinetic
hydrate inhibitor (KHI) from an aqueous composition containing
water and at least one polymeric KHI may consist of or consist
essentially of contacting the aqueous composition with a water
immiscible solvent having a polarity index greater than about 3 in
an amount effective to inhibit the precipitation of the polymeric
KHI.
[0038] The words "comprising" and "comprises" as used throughout
the claims is to interpreted "including but not limited to".
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